1. Field of the Disclosure
Generally, embodiments disclosed herein relate to systems and methods for processing returned drilling fluids. More specifically, embodiments disclosed herein relate to systems and methods for processing returned drilling fluids using vibratory separators and systems for dividing a separated return drill fluid. More specifically still, embodiments disclosed herein relate to modular systems and corresponding methods for separating and dividing a returned drilling fluid into component parts for disposal and reuse.
2. Background Art
Oilfield drilling fluid, often called “mud,” serves multiple purposes in the industry. Among its many functions, the drilling mud acts as a lubricant to cool rotary drill bits and facilitate faster cutting rates. Typically, the mud is mixed at the surface and pumped downhole at high pressure to the drill bit through a bore of the drillstring. Once the mud reaches the drill bit, it exits through various nozzles and ports where it lubricates and cools the drill bit. After exiting through the nozzles, the “spent” fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore.
Furthermore, drilling mud provides a column of hydrostatic pressure, or head, to prevent “blow out” of the well being drilled. This hydrostatic pressure offsets formation pressures, thereby preventing fluids from blowing out if pressurized deposits in the formation are breached. Two factors contributing to the hydrostatic pressure of the drilling mud column are the height (or depth) of the column (i.e., the vertical distance from the surface to the bottom of the wellbore) and the density (or its inverse, specific gravity) of the fluid used. Depending on the type and construction of the formation to be drilled, various weighting and lubrication agents are mixed into the drilling mud to obtain a desired mixture. Typically, drilling mud weight is reported in “pounds,” short for pounds per gallon. Generally, increasing the amount of weighting agent solute dissolved in the mud base will create a heavier drilling mud. Drilling mud that is too light may not protect the formation from blow outs, and drilling mud that is too heavy may over invade the formation. Therefore, much time and consideration is spent to ensure the mud mixture is optimal. Because the mud evaluation and mixture process is time consuming and expensive, drillers and service companies prefer to reclaim the returned drilling mud and recycle it for continued use.
An additional purpose of the drilling mud is to carry the cuttings away from the drill bit at the bottom of the borehole to the surface. As a drill bit pulverizes or scrapes the rock formation at the bottom of the borehole, small pieces of solid material are left behind. The drilling fluid exiting the nozzles at the bit acts to stir-up and carry the solid particles of rock and formation to the surface within the annulus between the drillstring and the borehole. Therefore, the fluid exiting the borehole from the annulus is a slurry of formation cuttings in drilling mud. Before the mud can be recycled and re-pumped down through nozzles of the drill bit, the cutting particulates must be removed.
Apparatus in use today to remove cuttings and other solid particulates from drilling fluid are commonly referred to in the industry as “shale shakers.” A shale shaker, also known as a vibratory separator, is a vibrating sieve-like table upon which returning solids laden drilling fluid is deposited and through which clean drilling fluid emerges. Typically, the shale shaker is an angled table with a generally perforated filter screen bottom. Returning drilling fluid is deposited at the feed end of the shale shaker. As the drilling fluid travels down a length of the vibrating table, the fluid falls through the perforations to a reservoir below leaving the solid particulate material on the table. The vibrating action of the shale shaker table conveys solid particles left behind until they fall off the discharge end of the shaker table. The above described apparatus is illustrative of one type of shale shaker known to those of ordinary skill in the art. In alternate shale shakers, the top edge of the shaker may be relatively closer to the ground than the lower end. In such shale shakers, the angle of inclination may require the movement of particulates in a generally upward direction. In still other shale shakers, the table may not be angled, thus the vibrating action of the shaker alone may enable particle/fluid separation. Regardless, table inclination and/or design variations of existing shale shakers should not be considered a limitation of the present disclosure.
Preferably, the amount of vibration and the angle of inclination of the shale shaker table are adjustable to accommodate various drilling fluid flow rates and particulate percentages in the drilling fluid. After the fluid passes through the perforated bottom of the shale shaker, it can either return to service in the borehole immediately, be stored for measurement and evaluation, or pass through an additional piece of equipment (e.g., a drying shaker, centrifuge, or a smaller sized shale shaker) to further remove smaller cuttings.
The vibratory motion of typical shakers is generated by one or more motors attached to the basket of the shaker. In such shakers, motors and actuation devices may be placed on or be integral to the basket. In typical shakers with basket mounted motors, screens and/or screen assemblies are attached to the shaker underneath the motors. The motion of the basket is transferred to the screens, such that as drilling fluid containing solid particles passes thereover, the fluid and fine solid matter passes through the screens while relatively larger solids remain on the screen surface. The solids are typically then transferred from the shaker to either a secondary separatory operation, or otherwise disposed of according to local rules and regulations.
However, in certain cleaning operations, the shakers may have multiple separatory surfaces including, for example, multiple screening surfaces and/or screens having filtering elements of different perforation size. In some shakers a first, large perforation screening surface (i.e., a scalping deck) is placed above a second, relatively smaller perforated screen surface (i.e., a fines deck), so that large solids remain on the top screening surface. Accordingly, fines pass though the scalping deck and, when they are larger than the perforations of the filtering element of the second screen surface, collect on top of the second screen surface. The large solids and the fines may then be disposed of or used in downstream operations accordingly.
The removal of low gravity solids (“LGS”) from returned drilling fluid is an important factor in an efficient drilling operation, as the presence of LGS are detrimental to the drilling process in a number of areas. If the concentration of LGS exceeds 3-5%, then a drilling process may experience a loss of rate of penetration, fluid loss, and loss of fluid viscosity.
Accordingly, there exists a continuing need for a method of processing a return drilling fluid that may efficiently clean a drilling fluid to allow for recycling of the fluid, as well as disposal of cuttings. Additionally, there exists a need for a system for processing return drilling fluid that may decrease the costs associated with controlling LGS and drilling fluid additive consumption.